Multiple-Interval Wellbore Stimulation System and Method

ABSTRACT

Disclosed are systems and methods for carrying out multiple-interval stimulation of a wellbore. One disclosed method includes introducing one or more wellbore projectiles into a work string including a completion assembly having a first downhole tool arranged within a first interval, a second downhole tool arranged within a second interval, and a third downhole tool arranged within a third interval that interposes the first and second intervals, detecting the one or more wellbore projectiles with first and second sensors of the first and second downhole tools, opening first and second sliding sleeves arranged within the first and second downhole tools, treating the first and second intervals, sealing the first and second intervals, detecting a wellbore projectile with a third sensor of the third downhole tool, opening a third sliding sleeve arranged within the third downhole tool, and treating the third interval independent of the first and second intervals.

BACKGROUND

The present disclosure relates generally to wellbore operations and,more particularly, to systems and methods for carrying outmultiple-interval stimulation of a wellbore.

Hydrocarbon-producing wells are often stimulated by hydraulic fracturingoperations in order to enhance the production of hydrocarbons present insubterranean formations. During a typical fracturing operation, aservicing fluid (i.e., a fracturing fluid or a perforating fluid) may beinjected into a subterranean formation penetrated by a wellbore at ahydraulic pressure sufficient to create or enhance fractures within thesubterranean formation. The resulting fractures serve to increase theconductivity potential for extracting hydrocarbons from the subterraneanformation.

In some wellbores, it may be desirable to selectively generate multiplefractures along the wellbore at predetermined distances apart from eachother, thereby creating multiple-interval “pay zones” in thesubterranean formation. Some pay zones may extend a substantial distancealong the axial length of the wellbore. In order to adequately fracturethe subterranean formation encompassing such zones, it may beadvantageous to introduce a stimulation fluid via multiple stimulationassemblies arranged within the wellbore at spaced apart locations on awork string extended therein. Each stimulation assembly may include, forexample, a sliding sleeve configured to be opened and shut in order toallow fluid communication between the interior of the work string andthe surrounding subterranean formation.

Alternatively, each interval can be treated using a method known as“plug-and-perf” where charges are run in hole using wireline or coiledtubing. Once downhole, the charges are then fired to create perforationsin the casing string. The interval may then be treated by pumpingproppant fluids into the interval. A plug is then run on wireline orcoiled tubing to seal the wellbore such that the first perforations arethen below the plug and therefore sealed from the wellbore above. Moreperforations are then created using the process previously mentioned,and those perforations are created above the plug. This interval is thentreated, and the process is then repeated as many times as desiredmoving upwards within the wellbore.

One method recently implemented for multiple-interval fracturing is thealternate sequence fracturing “ASF” process. One ASF process that is nowbeing used is referred to as the “Texas Two-Step” method. This methodinvolves conventional fracturing of individual intervals in a singlewell, but with a change in the sequence by which the formationfracturing is undertaken. The method starts at the toe of the well wherea first interval is stimulated by hydraulic fracturing. Then, movingupwards within the well towards the heel, a second interval isstimulated such that a degree of interference between the two fracturesis generated. A third interval is then stimulated between the first andsecond previously fractured intervals, thereby taking advantage of thealtered stress in the rock by fluidly connecting to stress-relieffractures generated from the first and second fractures.

The Texas Two-Step method takes advantage of sliding sleeve technologywhere each interval is defined by at least one sliding sleeve and anannular wellbore isolation device (e.g., wellbore packer) arranged atopposing axial ends of each interval. The process of stimulating eachinterval using this method, however, can be a time-consuming processrequiring multiple trips into the wellbore with wireline and/or coiledtubing tools to accomplish the job. This disadvantage is furtherexacerbated in wells where multiple Texas Two-Step operations areundertaken. Alternatively, alternating sequence fracturing can beperformed by other methods involving coiled tubing. These processes,however, are also time intensive and costly.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1 is a schematic of an exemplary well system which can embody orotherwise employ one or more principles of the present disclosure,according to one or more embodiments.

FIGS. 2A-2D illustrate progressive partial cut-away views of one of thedownhole tools of FIG. 1, according to one or more embodiments.

FIG. 3 illustrates a cross-sectional view of a completion assembly ofthe well system of FIG. 1 during a first stage of operation, accordingto one or more embodiments.

FIG. 4 illustrates a cross-sectional view of a completion assembly ofthe well system of FIG. 1 during a second stage of operation, accordingto one or more embodiments.

FIG. 5 illustrates a cross-sectional view of a completion assembly ofthe well system of FIG. 1 during a third stage of operation, accordingto one or more embodiments.

FIGS. 6A and 6B illustrate separate isometric views of an exemplarywellbore projectile that may be used in the systems described herein,according to one or more embodiments.

FIG. 7 is a schematic diagram of a method of treating multiple intervalsof a formation, according to one or more embodiments disclosed.

DETAILED DESCRIPTION

The present disclosure relates generally to wellbore operations and,more particularly, to systems and methods for carrying outmultiple-interval stimulation of a wellbore.

The present disclosure provides an improved method and system ofstimulating or treating multiple intervals in a wellbore without theneed to run into the wellbore multiple times with coiled tubing orwireline. More particularly, the disclosed systems may include at leastthree sliding sleeve assemblies arranged to treat three corresponding,laterally spaced pay zones or intervals in a subterranean formation.Each assembly may include a sensor configured to detect a wellboreprojectile, such as a frac ball, that exhibits magnetic properties. Oneor more wellbore projectiles may interact with the first and thirdsliding sleeve assemblies, thereby allowing the first and thirdintervals to be treated simultaneously while the second interposinginterval remains shut. Following stimulation of the first and thirdintervals, a diverting agent may be used to temporarily seal the firstand third intervals.

A third magnetic wellbore projectile may then be used to interact withthe second sliding sleeve assembly, thereby allowing the second intervalto be treated while the first and third intervals are temporarilysealed. Once the diverting agent that sealed first and third intervalsdegrades, the wellbore projectiles may each be returned to the surfaceunder pressure derived from the various intervals, and productionoperations may then commence. Advantageously, each of the threeintervals may be stimulated and produced without having to run into thewellbore multiple times to shift sleeves using shifting tools coupled tocoiled tubing or wireline. As a result, a significant amount of time andcost is saved.

Referring to FIG. 1, illustrated is an exemplary well system 100 whichcan embody or otherwise employ one or more principles of the presentdisclosure, according to one or more embodiments. As illustrated, thewell system 100 may include an oil and gas rig 102 arranged at theEarth's surface 104 and a wellbore 106 extending therefrom andpenetrating a subterranean earth formation 108. Even though FIG. 1depicts a land-based oil and gas rig 102, it will be appreciated thatthe embodiments of the present disclosure are equally well suited foruse in other types of rigs, such as offshore platforms, or rigs used inany other geographical location. In other embodiments, the rig 102 maybe replaced with a wellhead installation, without departing from thescope of the disclosure.

The rig 102 may include a derrick 110 and a rig floor 112, and thederrick 110 may support or otherwise help manipulate the axial positionof a work string 114 extended within the wellbore 106 from the rig floor112. As used herein, the term “work string” refers to one or more typesof connected lengths of tubulars such as drill pipe, drill string,landing string, production tubing, coiled tubing combinations thereof,or the like. In exemplary operation, the work string 114 may be utilizedin drilling, stimulating, completing, or otherwise servicing thewellbore 106, or various combinations thereof.

As illustrated, the wellbore 106 may extend substantially verticallyaway from the surface 104 over a vertical wellbore portion. In otherembodiments, the wellbore 106 may otherwise deviate at any angle fromthe surface 104 over a deviated or horizontal wellbore portion. In otherapplications, portions or substantially all of the wellbore 106 may bevertical, deviated, horizontal, and/or curved. Moreover, use ofdirectional terms such as above, below, upper, lower, upward, downward,uphole, downhole, and the like are used in relation to the illustrativeembodiments as they are depicted in the figures, the upward directionbeing toward the top of the corresponding figure and the downwarddirection being toward the bottom of the corresponding figure, theuphole direction being toward the heel or surface of the well and thedownhole direction being toward the toe or bottom of the well.

In an embodiment, the wellbore 106 may be at least partially cased witha casing string 116 or may otherwise remain at least partially uncased.The casing string 116 may be secured within the wellbore 106 using, forexample, cement 118. In other embodiments, the casing string 116 may beonly partially cemented within the wellbore 106 or, alternatively, thecasing string 116 may be entirely un-cemented, without departing fromthe scope of the disclosure. The work string 114 may be coupled to acompletion assembly 119 that extends into a branch or lateral portion120 of the wellbore 106. As illustrated, the lateral portion 120 may bean uncased or “open hole” section of the wellbore 106. It is noted thatalthough FIG. 1 depicts horizontal and vertical portions of the wellbore106, the principles of the apparatus, systems, and methods disclosedherein may be similarly applicable to or otherwise suitable for use inwholly horizontal or vertical wellbore configurations. Consequently, thehorizontal or vertical nature of the wellbore 106 should not beconstrued as limiting the present disclosure to any particular wellbore106 configuration.

The completion assembly 119 may be arranged or otherwise seated withinthe lateral portion 120 of the wellbore 106 using one or more packers122 or other wellbore isolation devices known to those skilled in theart. The packers 122 may be configured to seal off an annulus 124defined between the completion assembly 119 and the walls of thewellbore 106. As a result, the subterranean formation 108 may beeffectively divided into multiple intervals or “pay zones” 126 (shown asintervals 126 a, 126 b, and 126 c) which may be stimulated and/orproduced independently via isolated portions of the annulus 124 definedbetween adjacent pairs of packers 122. While only three intervals 126a-c are shown in FIG. 1, those skilled in the art will readily recognizethat any number of intervals 126 a-c may be defined or otherwise used inthe well system 100, without departing from the scope of the disclosure.

The completion assembly 119 may include one or more downhole tools 128(shown as 128 a, 128 b, and 128 c) arranged in, coupled to, or otherwiseforming an integral part of the work string 114. As illustrated, atleast one downhole tool 128 a-c may be arranged in the completionassembly 119 in each interval 126 a-c, but those skilled in the art willreadily appreciate that more than one downhole tool 128 may be arrangedtherein, without departing from the scope of the disclosure. Thedownhole tools 128 a-c may include a variety of tools, devices, ormachines known to those skilled in the art used in the preparation,stimulation, and production of the subterranean formation 108.

In the illustrated embodiment, however, the downhole tool 128 a-c ineach interval 126 a-c may include or otherwise encompass a slidingsleeve assembly that may be actuated in order to provide fluidcommunication between the interior of the work string 114 and theannulus 124 adjacent each corresponding interval 126 a-c. As depicted,each downhole tool 128 a-c may include a sliding sleeve 130 that isaxially movable to expose one or more ports 132 defined in thecorresponding body of the work string 114 or downhole tool 128 a-c. Onceexposed, the ports 132 may facilitate fluid communication between theannulus 124 and the interior of the work string 114 such thatstimulation and production operations may be undertaken in eachcorresponding interval 126 a-c of the formation 108.

It should be noted that, while the downhole tools 128 a-c are shown inFIG. 1 as being employed in an open hole section of the wellbore 106,the principles of the present disclosure are equally applicable tocompleted or cased sections of the wellbore 106. In such embodiments,the cased wellbore 106 may be perforated at predetermined locations ineach interval 126 a-c using any known methods (e.g., explosives,hydrajetting, etc.) in the art. Such perforations serve to facilitatefluid conductivity between the interior of the work string 114 and thesurrounding intervals 126 a-c of the formation 108.

In order to actuate, trigger, or manipulate the downhole tools 128 a-cand thereby expose the corresponding ports 132, one or more wellboreprojectiles 134 (shown in FIG. 1 as projectiles 134 a and 134 b) may beintroduced into the wellbore 106 and conveyed to the downhole tools 128a-c to engage or otherwise interact therewith. The wellbore projectiles134 may include, but are not limited to balls (e.g., “frac” balls),darts, wipers, plugs, or any combination thereof. The wellboreprojectiles 134 may be conveyed through the work string 114 and to thecompletion assembly 119 by any known technique. For example, thewellbore projectiles 134 can be dropped through the work string 114 fromthe surface 104, pumped by flowing fluid through the interior of thework string 114, self-propelled, conveyed by wireline, slickline, coiledtubing, etc.

Each wellbore projectile 134 may further exhibit known magneticproperties, and/or produce a known magnetic field, pattern, orcombination of magnetic fields, which is/are detected by one or moresensors 136 (shown as sensors 136 a, 136 b, and 136 c) associated witheach downhole tool 128 a-c. Each sensor 136 a-c can include any type ofsensor capable of detecting the presence of the magnetic field(s)produced by the wellbore projectiles 134 and/or one or more othermagnetic properties of the wellbore projectiles 134. Suitable sensors136 a-c can include, but are not limited to, magneto-resistive sensors,Hall-effect sensors, conductive coils, combinations thereof, and thelike. In some embodiments, permanent magnets can be combined with one ormore of the sensors 136 a-c in order to create a magnetic field that isdisturbed by the wellbore projectiles 134, and a detected change in themagnetic field can be an indication of the presence of the wellboreprojectiles 134.

Each sensor 136 a-c may be connected to associated electronic circuitry(not shown in FIG. 1) which determines whether the associated sensor hasdetected a particular predetermined magnetic field, or pattern orcombination of magnetic fields, or other magnetic properties of thewellbore projectiles 134. For example, the electronic circuitry couldhave the predetermined magnetic field(s) or other magnetic propertiesprogrammed into non-volatile memory for comparison to magneticfields/properties detected by the associated sensor.

Once a wellbore projectile 134 is detected by the sensors 136 a-c, theelectronic circuitry may trigger actuation of the corresponding downholetool 128 a-c using one or more associated actuation devices (not shownin FIG. 1). In some embodiments, however, actuation of the associateddownhole tool 128 a-c may not be triggered until a predetermined numberor combination of wellbore projectiles 134 has been detected by thesensor 136 a-c. In other embodiments, actuation of the associateddownhole tool 128 a-c may not be triggered until a predetermined timeperiod has passed following detection of a wellbore projectile 134 or apredetermined number or combination thereof.

In the illustrated example, a first wellbore projectile 134 a has beenintroduced into the work string 114 and conveyed past each of thesensors 136 a-c such that each sensor 136 a-c is able to detect andotherwise record its proximity and/or presence. In some embodiments, inresponse to sensing or otherwise detecting the first wellbore projectile134 a, the third sensor 136 c may be configured to trigger actuation ofthe corresponding third downhole tool 128 c. More particularly, once thethird sensor 136 c detects the first wellbore projectile 134 a,associated electronic circuitry may trigger the actuation of a baffleseat (not shown in FIG. 1) arranged within the third downhole tool 128c. As described in greater detail below with reference to FIGS. 2A-2D,the baffle seat of the third downhole tool 128 c may be configured tocatch and retain a subsequent wellbore projectile 134 (e.g., the secondwellbore projectile 134 b) conveyed downhole.

Referring now to FIGS. 2A-2D, with continued reference to FIG. 1,illustrated are progressive partial cut-away views of the third downholetool 128 c, according to one or more embodiments. Similar referencenumerals used in FIG. 1 and FIGS. 2A-2D correspond to similar componentsthat will not be described again in detail. The following discussion ofthe third downhole tool 128 c may be generally descriptive also of thesecond downhole tool 128 b, without departing from the scope of thedisclosure. As illustrated, the third downhole tool 128 c may be coupledat each end to opposing portions of the work string 114. In at least oneembodiment, the third downhole tool 128 c may be similar in somerespects to the injection valves disclosed in co-owned U.S. patentapplication Ser. No. 13/219,790.

In FIG. 2A, the downhole tool 128 c is depicted in a “run-in” or closedconfiguration, where the sleeve 130 generally occludes the ports 132defined in the body 202 of the tool 128 c. The first wellbore projectile134 a is shown in FIG. 2A downhole from the third sensor 136 c andproceeding in a downhole direction (e.g., to the right in FIG. 2A). Asthe first wellbore projectile 134 a passes by the third sensor 136 c,electronic circuitry 204 associated with the sensor 136 c may determinethat a predetermined magnetic field(s) or change(s) in magnetic field(s)of the first wellbore projectile 134 a has been detected. As a result,the electronic circuitry 204 may be configured to actuate the thirddownhole tool 128 c. In alternative embodiments, as briefly mentionedabove, the electronic circuitry 204 may be configured to actuate thethird downhole tool 128 c following the detection of a predeterminednumber or combination of wellbore projectiles 134, or following apredetermined time period after detection of the first wellboreprojectile 134 a or a predetermined number or combination of wellboreprojectiles 134.

Once the appropriate signal (e.g., magnetic property or properties) hasbeen detected or otherwise sensed, the electronic circuitry 204 maycause that a retractable baffle 206 extend a short distance into theinterior of the downhole tool 128 c, as depicted in FIG. 2B. This may beaccomplished by triggering an actuator 208 associated with the thirddownhole tool 128 c. The actuator 208 may be any mechanical,electro-mechanical, hydraulic, or pneumatic actuation device capable ofmanipulating the configuration or position of the baffle 206. In atleast one embodiment, the actuator 208 may be an electro-hydraulicpiston lock similar to the devices disclosed in U.S. patent applicationSer. No. 13/219,790. Briefly, the actuator 208 may include a piercingmember (not shown) configured to pierce a pressure barrier (not shown)that initially isolates first and second chambers (not shown). Once thepressure barrier is pierced, a support fluid flows from the firstchamber to the second chamber, thereby generating a pressuredifferential across the sleeve 130 that displaces the sleeve downward(e.g., to the right in FIGS. 2A-2D).

Referring to FIG. 2B, as the sleeve 130 moves downward, it engages orotherwise contacts an axial end of the baffle 206, thereby forcing thebaffle 206 axially against a baffle containment sleeve 210 arranged onthe inner wall of the downhole tool 128 c. The baffle 206 may be aretractable landing seat in the form of an expandable ring. As thebaffle 206 is forced axially against the baffle containment sleeve 210by the sleeve 130, the baffle 206 contracts radially and otherwiseextends inwardly to a sealing position, as shown in FIG. 2B. In itssealing position, the baffle 206 may be configured to receive and seat awellbore projectile 134, such as the second wellbore projectile 134 b.

Referring to FIG. 2C, the second wellbore projectile 134 b has beenintroduced into the work string 114, conveyed to the third downhole tool128 c, and subsequently received by the baffle 206 extended into itssealing position. Once seated on the baffle 206, the second wellboreprojectile 134 b may be configured to substantially seal the interior ofthe downhole tool 128 c such that fluids are generally prevented frompassing downhole past that point within the work string 114 (FIG. 1).

Referring to FIG. 2D, the work string 114 may then be pressurized fromthe surface 104 (FIG. 1) uphole from the baffle 206 and the secondwellbore projectile 134 b. Upon increasing the pressure within theinterior of the work string 114, the second wellbore projectile 134 bmay force the baffle containment sleeve 210 axially downhole a shortdistance until engaging a shoulder 212 (best seen in FIG. 2C), therebyallowing the sleeve 130 to fully open and expose the ports 132 definedin the body 202. The third downhole tool 128 c is shown in FIG. 2D inits open configuration, where the ports 132 are exposed and thereforeable to facilitate fluid communication into and out of the work string114. With the third downhole tool 128 c in the open configuration, afracturing or stimulation fluid may be injected into the surroundinginterval 126 c (FIG. 1) via the ports 132, as will be discussed below.

Referring now to FIG. 3, with continued reference to FIG. 1, illustratedis a cross-sectional view of the completion assembly 119 of the wellsystem 100 of FIG. 1 during a first stage of exemplary operation,according to one or more embodiments. As illustrated, the secondwellbore projectile 134 b is sealingly engaged in the third downholetool 128 c, as generally described above. Upon pressurizing the workstring 114, the second wellbore projectile 134 b allows the sleeve 130associated with the third downhole tool 128 c to move axially and exposethe corresponding ports 132, thereby facilitating fluid communicationbetween the annulus 124 and the interior of the work string 114 suchthat the third interval 126 c of the formation 108 may be treated.

In some embodiments, the second wellbore projectile 134 b may further beconfigured to trigger actuation of the first downhole tool 128 a. Moreparticularly, the first sensor 136 a of the first downhole tool 128 amay be configured to detect the second wellbore projectile 134 b and,upon detection thereof, may be configured to trigger an actuation device(not shown) associated with the first downhole tool 128 a. The actuationdevice of the first downhole tool 128 a may be an electromechanical orhydraulic actuation device configured to facilitate axial movement ofits associated sleeve 130 to an open configuration. In the openconfiguration, as shown in FIG. 3, the one or more ports 132 defined inthe work string 114 at that point may be exposed, thereby facilitatingfluid communication between the annulus 124 and the interior of the workstring 114 such that the first interval 126 a of the formation 108 maybe treated.

In at least one embodiment, actuation of the first downhole tool 128 amay be time delayed. More specifically, the electronic circuitry (notshown) associated with the first sensor 136 a may be configured to delayactuation of the first downhole tool 128 a until after a predeterminedtime period has expired following detection of the second wellboreprojectile 134 b. The predetermined time period may provide sufficienttime to pressurize the work string 114 in order to fully actuate thethird downhole tool 128 c prior to opening the sleeve 130 of the firstdownhole tool 128 a. The predetermined time period may range from about2 minutes to about 10 minutes. Those skilled in the art, however, willreadily appreciate that the predetermined time delay may be more than 10minutes, without departing from the scope of the disclosure.

With the sleeves 130 of each of the first and third downhole tools 128 aand 128 c in their respective open configurations, the first and thirdintervals 126 a and 126 c may be treated. It is noted that at this timethe sleeve 130 of the second downhole tool 128 b remains in its closedposition, thereby occluding the ports 132 of the second downhole tool128 b. Treating the first and third intervals 126 a,c may includeintroducing or otherwise injecting a fracturing fluid 302 into eachinterval 126 a,c via the exposed ports 132 of the first and thirddownhole tools 128 a,c. The fracturing fluid 302 is hydraulically forcedinto the formation 108 through the ports 132, thereby generating andpropagating a network of fractures 304 (shown as fractures 304 a and 304c) in each of the first and third intervals 126 a,c. In someembodiments, the fracturing fluid 302 may include a proppant slurry orother particulate matter configured to prop open the fractures 304 a,conce the hydraulic pressure is reduced.

As illustrated, the fractures 304 a,c may extend generally radiallyoutward from the wellbore 106 and generally within each correspondinginterval 126 a,c. At least some of the fractures 304 a,c, however, mayextend laterally into the second interval 126 b as a degree ofinterference between the first and third networks of fractures 304 a,cis generated.

Referring now to FIG. 4, with continued reference to FIG. 3, illustratedis a cross-sectional view of the completion assembly 119 of the wellsystem 100 of FIG. 1 during a second stage of exemplary operation,according to one or more embodiments. Following the stimulationtreatment of the first and third intervals 126 a,c, a diverting agent402 may be introduced or otherwise injected into each interval 126 a,cvia the exposed ports 132 of the first and third downhole tools 128 a,c.In other embodiments, the diverting agent 402 may be introduced intoeach interval 126 a,c as an integral part of the stimulation operation,without departing from the scope of the disclosure. Again, it is notedthat the sleeve 130 of the second downhole tool 128 b remains in itsclosed position, thereby occluding the ports 132 of the second downholetool 128 b and preventing the diverting agent 402 from exiting thesecond downhole tool 128 b into the second interval 126 b.

The diverting agent 402, also known as a chemical diverter, may be usedto temporarily seal or block off the fractured first and third intervals126 a,c, such that subsequent injections of fracturing fluids may bediverted to other intervals, such as the second interval 126 b. Whenbeing introduced into the first and third intervals 126 a,c, thediverting agent 402 will flow most readily into portions of the firstand third intervals 126 a,c having the largest pores, fissures, or vugs,until those portions are bridged and sealed, thus diverting theremaining fluid to the next most permeable portion of the formation 108.

In some embodiments, the diverting agent 402 may be at least partiallydegradable. In at least one embodiment, the diverting agent 402 may be adiverting agent from the BIOVERT series of degradable diverting agentscommercially available through Halliburton Energy Services of HoustonTex., USA. Other suitable diverting agents 402 that may be used include,but are not limited to, mineral particles (e.g., calcium carbonate,magnesium oxide, zinc oxide, zinc carbonate and calcium sulfate),degradable polymers (e.g., polysaccharides such as dextran or cellulose,chitins, chitosans, proteins, aliphatic polyesters, poly(lactides),poly(glycolides), poly(ε-caprolactones), poly(hydroxybutyrates),poly(anhydrides), aliphatic polycarbonates, poly(orthoesters),poly(amino acids), poly(ethylene oxides), and polyphosphazenes),dehydrated compounds (e.g., solid anhydrous borate material), andcombinations thereof.

Any particulates used in the diverting agent 402 include materialparticles having the physical shape of platelets, shavings, flakes,ribbons, rods, strips, spheroids, toroids, pellets, tablets or any otherphysical shape. The size of the particles of the diverting agent used tocarry out the method of the invention will vary over a wide rangedepending upon the formation to be treated. The terms “degrade,”“degradation,” “degradable,” and the like, when used herein refer toboth the two relative cases of hydrolytic degradation that thedegradable diverting agent 402 may undergo; i.e., heterogeneous (or bulkerosion) and homogeneous (or surface erosion), and any stage ofdegradation in between these two. This degradation can be a result ofinter alia, a chemical or thermal reaction or a reaction induced byradiation.

Referring now to FIG. 5, with continued reference to FIGS. 3 and 4,illustrated is a cross-sectional view of the completion assembly 119 ofthe well system 100 of FIG. 1 during a third stage of exemplaryoperation, according to one or more embodiments. With the first andthird intervals 126 a,c successfully treated (e.g., hydraulicallyfractured) and sealed using the diverting agent 402 (FIG. 4), the seconddownhole tool 128 b may be actuated such that the second interval 126 bmay also be treated. In some embodiments, the second wellbore projectile134 b may further be configured to trigger actuation of the sectiondownhole tool 128 b. More particularly, the second sensor 136 b of thesecond downhole tool 128 a may be configured to detect the secondwellbore projectile 134 b and, upon detection thereof, may be configuredto trigger an actuation device (not shown) associated with the seconddownhole tool 128 b.

As briefly mentioned above, the second downhole tool 128 b may besubstantially similar to the third downhole tool 128 c described abovewith reference to FIGS. 2A-2D. Accordingly, operation of the seconddownhole tool 128 b may be best understood with reference to FIGS.2A-2D. More particularly, as the second wellbore projectile 134 b passesby the second sensor 136 b of the second downhole tool 128 b, theassociated electronic circuitry may determine that a predeterminedmagnetic property of the second wellbore projectile 134 b has beendetected. Alternatively, the associated electronic circuitry maydetermine that a predetermined number or combination of wellboreprojectiles 134 (e.g., first and second projectiles 134 a,b) has beenaffirmatively detected by the second sensor 136 b.

Once the appropriate signal has been detected or otherwise sensed by thesecond sensor 136 b, the associated electronic circuitry may cause thata retractable baffle (similar to the baffle 206 of FIGS. 2A-2D) extend ashort distance into the interior of the second downhole tool 128 b andotherwise move into its sealing position (similar to FIG. 2B). This maybe accomplished by moving the sleeve 130 axially downward, as generallydescribed above with reference to FIGS. 2A-2D. In its sealing position,the baffle of the second downhole tool 128 b may be configured toreceive and seat a wellbore projectile 134, such as the third wellboreprojectile 134 c depicted in FIG. 5.

Once properly seated on the baffle of the second downhole tool 128 b,the third wellbore projectile 134 c may be configured to substantiallyseal the interior of the second downhole tool 128 b such that fluids aregenerally prevented from passing downhole past that point within thework string 114. The work string 114 may then be pressurized from thesurface 104 (FIG. 1), in order to act on the seated third wellboreprojectile 134 c and thereby move the sleeve 130 of the second downholetool 128 b axially downhole to its open configuration, as depicted inFIG. 5. In its open configuration, the ports 132 of the second downholetool 128 b may be exposed and otherwise facilitate fluid communicationinto and out of the work string 114 at that location.

With the sleeve 130 of the second downhole tool 128 b in its openconfiguration, the second interval 126 b may then be treated (i.e.,hydraulically fractured). This may be accomplished by introducing orotherwise injecting fracturing fluid 302 into the interval 126 b via theexposed ports 132 of the second downhole tool 128 b. Since the firstinterval 126 a is substantially sealed with the diverting agent 402(FIG. 4), the fracturing fluid 302 may generally bypass the ports 132 ofthe first downhole tool 128 a, and instead locate the ports 132 of thesecond downhole tool 128 b. At the second downhole tool 128 b, thefracturing fluid 302 is hydraulically forced into the formation 108through the ports 132, thereby generating and propagating a network offractures 304 b in the second interval 126 b that extend generallyradially outward from the wellbore 106.

The fractures 304 b formed in the second interval 126 b may takeadvantage of the altered stress in the formation rock previously causedby the fracturing of the first and third intervals 126 a,c. Asillustrated, a portion of the fractures 304 b associated with the secondinterval 126 b may extend laterally and potentially overlap with thefractures 304 a,c of the first and third intervals 126 a,c,respectively. As a result, a highly conductive network of fractures 304a-c is generated and extends across each of the intervals 126 a-c. Overtime, the diverting agent 402 used to seal the first and third intervals126 a,c may degrade, thereby allowing fluid conductivity once againthrough each of the fractures 304 a,c. Prior to commencing productionoperations, the wellbore projectiles 134 a-c may be returned to thesurface 104 (FIG. 1) using, for example, zonal pressure derived fromeach interval 126 a-c.

Referring additionally now to FIGS. 6A and 6B, illustrated areindividual isometric views of an exemplary wellbore projectile 134 thatmay be used in the system 100 (FIG. 1), according to one or moreembodiments. As illustrated, the wellbore projectile 134 is in thegeneral shape of a sphere 602, such as a frac ball known to thoseskilled in the art. In this example, magnets (not shown in FIGS. 6A and6B) may be retained in a plurality of recesses 604 defined in the outersurface of the sphere 602. In other embodiments, however, the magnet(s)of the wellbore projectile 134 may be disposed entirely within thecenter of the sphere 602, without departing from the scope of thedisclosure.

In some embodiments, the recesses 604 may be arranged in a patternwhich, in this case, resembles that of stitching on a baseball. Moreparticularly, the pattern shown in FIGS. 6A and 6B encompasses spacedapart positions distributed along a continuous undulating path about thesphere 602. However, it should be clearly understood that any pattern ofmagnetic field-producing components may be used in the wellboreprojectile 134, in keeping with the scope of this disclosure. Indeed,the magnets may be arranged to provide a magnetic field that extends apredetermined distance from the wellbore projectile 134, and to do so nomatter the orientation of the sphere 602. The pattern depicted in FIGS.6A and 6B may be configured to project the produced magnetic field(s)substantially evenly around the sphere 602.

Referring now to FIG. 7, with continued reference to FIG. 1, illustratedis a schematic diagram of a method 700 of treating multiple intervals ofa formation, according to one or more embodiments disclosed. The method700 may include introducing one or more wellbore projectiles into a workstring, as at 702. The work string may be arranged at least partiallywithin a formation 108 and include a completion assembly. The completionassembly may include a first downhole tool 128 a arranged adjacent afirst interval 126 a of the formation 108 and a second downhole tool 128b arranged within a second interval 126 c of the formation 108. Thecompletion assembly may further include a third downhole tool 126 barranged adjacent a third interval 126 b that interposes the first andsecond intervals 126 a,c.

The method 700 may further include detecting the one or more wellboreprojectiles with a first sensor 136 a of the first downhole tool 128 aand a second sensor 136 c of the second downhole tool 128 b, as at 704.First and second sliding sleeves 130 arranged within the first andsecond downhole tools 128 a,c may then be opened following detection ofthe one or more wellbore projectiles, as at 706. The first and secondintervals 126 a,c may then be treated, as at 708, and the first andsecond intervals 126 a,c are then sealed, as at 710. In at least oneembodiment, this may be done by injecting a diverting agent into thefirst and second intervals.

The method 700 may further include detecting the one or more wellboreprojectiles with a third sensor 136 b of the third downhole tool 128 b,as at 712. A third sliding sleeve 130 arranged within the third downholetool 128 b may then be opened following detection of the one or morewellbore projectiles, as at 714. The third interval 126 b may then betreated independent of the first and second intervals 126 a,c, as at716.

Embodiments disclosed herein include:

A. A well system that includes one or more wellbore projectilesintroduced into a completion assembly, and a first downhole toolarranged in the completion assembly adjacent a first interval and havinga first sensor that triggers actuation of a first sleeve upon detectingthe one or more wellbore projectiles. The well system further includes asecond downhole tool arranged in the completion assembly downhole fromthe first downhole tool and adjacent a second interval, the seconddownhole tool having a second sensor that triggers actuation of a secondsleeve upon detecting the one or more wellbore projectiles, and a thirddownhole tool arranged in the completion assembly downhole from thesecond downhole tool and adjacent a third interval, the third downholetool having a third sensor that triggers actuation of a third sleeveupon detecting the one or more wellbore projectiles, wherein actuationof the first and third sleeves is triggered such that the first andthird intervals are stimulated simultaneously, and wherein actuation ofthe second sleeve is triggered such that the second interval isstimulated independent of the first and third intervals.

B. A method is also disclosed. The method may include introducing one ormore wellbore projectiles into a work string arranged at least partiallywithin a formation, the work string including a completion assemblyhaving a first downhole tool arranged adjacent a first interval, asecond downhole tool arranged adjacent a second interval, and a thirddownhole tool arranged adjacent a third interval that interposes thefirst and second intervals, detecting the one or more wellboreprojectiles with a first sensor of the first downhole tool and a secondsensor of the second downhole tool, opening first and second slidingsleeves arranged within the first and second downhole tools,respectively, following detection of the one or more wellboreprojectiles, treating the first and second intervals, sealing the firstand second intervals by injecting a diverting agent into the first andsecond intervals, detecting the one or more wellbore projectiles with athird sensor of the third downhole tool, opening a third sliding sleevearranged within the third downhole tool following detection of the oneor more wellbore projectiles, and treating the third intervalindependent of the first and second intervals.

C. Another method is disclosed. The method may include detecting a firstwellbore projectile with a first sensor associated with a first downholetool arranged adjacent a first interval, detecting a second wellboreprojectile with a second sensor associated with a second downhole tooland thereby causing the second downhole tool to actuate, the seconddownhole tool being arranged adjacent a second interval uphole from thefirst interval, actuating the first downhole tool by catching the secondwellbore projectile on a first baffle associated with the first downholetool and subsequently pressurizing the work string, detecting the secondwellbore projectile with a third sensor associated with a third downholetool interposing the first and second downhole tools and arrangedadjacent a third interval that interposes the first and secondintervals, hydraulically fracturing the first and second intervals viathe first and second downhole tools, respectively, sealing the first andsecond intervals by injecting a diverting agent into the first andsecond intervals, actuating the third downhole tool by catching a thirdwellbore projectile on a second baffle associated with the thirddownhole tool and subsequently pressurizing the work string, andhydraulically fracturing the third interval.

Each of embodiments A, B, and C may have one or more of the followingadditional elements in any combination: Element 1: wherein the first,second, and third sleeves are movable to expose ports that provide fluidcommunication into the first, second, and third intervals, respectively.Element 2: wherein the one or more wellbore projectiles are selectedfrom the group comprising balls, darts, wipers, and plugs. Element 3:wherein the one or more wellbore projectiles exhibit known magneticproperties detectable by the first, second, and third sensors. Element4: further comprising electronic circuitry associated with each of thefirst, second, and third sensors, the electronic circuitry beingconfigured to determine whether the corresponding first, second, andthird sensors have detected the known magnetic properties of the one ormore wellbore projectiles, and one or more actuation devices associatedwith the electronic circuitry of each of the first, second, and thirdsensors, the one or more actuation devices being configured tofacilitate moving the first, second, and third sleeves from open toclosed positions upon being directed by the electronic circuitry.Element 5: further comprising a diverting agent injected into the firstand third intervals such that the second interval can be stimulatedindependent of the first and second intervals following injection of thediverting agent.

Element 6: wherein detecting the one or more wellbore projectiles withthe first sensor of the first downhole tool and the second sensor of thesecond downhole tool further comprises detecting a magnetic property ofthe one or more wellbore projectiles with the first and second sensors.Element 7: wherein opening the first and second sliding sleevescomprises exposing a plurality of ports defined in both the first andsecond downhole tools, and facilitating fluid communication between aninterior of the work string and the first and second intervals throughthe plurality of ports. Element 8: wherein treating the first and secondintervals and treating the third interval comprise hydraulicallyfracturing the first, second, and third intervals. Element 9: whereindetecting the one or more wellbore projectiles with the third sensor ofthe third downhole tool comprises detecting a magnetic property of theone or more wellbore projectiles with the third sensor. Element 10:opening the third sliding sleeve comprises exposing a plurality of portsdefined in the third downhole tool, and facilitating fluid communicationbetween an interior of the work string and the third interval throughthe plurality of ports. Element 11: further comprising allowing thediverting agent to degrade in the first and second intervals, andproducing fluids from the first, second, and third intervals via thefirst, second, and third downhole tools, respectively.

Element 12: wherein detecting the first wellbore projectile with thefirst sensor comprises detecting a magnetic property of the firstwellbore projectile with the first sensor, and actuating the firstbaffle in response to the magnetic property being detected. Element 13:wherein actuating the first downhole tool comprises moving a slidingsleeve from a closed position to an open position where one or moreports are exposed and provide fluid communication with the firstinterval. Element 14: wherein detecting the second wellbore projectilewith the second sensor comprises detecting a magnetic property of thesecond wellbore projectile with the second sensor, and moving a slidingsleeve from a closed position to an open position with an actuationdevice associated with the second downhole tool, wherein, when in theopen position, one or more ports are exposed and provide fluidcommunication with the second interval. Element 15: further comprisingactuating the second downhole tool after a predetermined time periodexpires following detection of the second wellbore projectile by thesecond sensor. Element 16: wherein detecting the second wellboreprojectile with the third sensor associated with the third downhole toolcomprises detecting a magnetic property of the second wellboreprojectile with the third sensor, and actuating the second baffle inresponse to the magnetic property being detected. Element 17: furthercomprising allowing the diverting agent to degrade in the first andsecond intervals, and producing fluids from the first, second, and thirdintervals via the first, second, and third downhole tools, respectively.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

What is claimed is:
 1. A well system, comprising: one or more wellboreprojectiles introduced into a completion assembly; a first downhole toolarranged in the completion assembly adjacent a first interval and havinga first sensor that triggers actuation of a first sleeve upon detectingthe one or more wellbore projectiles; a second downhole tool arranged inthe completion assembly downhole from the first downhole tool andadjacent a second interval, the second downhole tool having a secondsensor that triggers actuation of a second sleeve upon detecting the oneor more wellbore projectiles; and a third downhole tool arranged in thecompletion assembly downhole from the second downhole tool and adjacenta third interval, the third downhole tool having a third sensor thattriggers actuation of a third sleeve upon detecting the one or morewellbore projectiles, wherein actuation of the first and third sleevesis triggered such that the first and third intervals are stimulatedsimultaneously, and wherein actuation of the second sleeve is triggeredsuch that the second interval is stimulated independent of the first andthird intervals.
 2. The well system of claim 1, wherein the first,second, and third sleeves are movable to expose ports that provide fluidcommunication into the first, second, and third intervals, respectively.3. The well system of claim 1, wherein the one or more wellboreprojectiles is selected from the group comprising balls, darts, wipers,and plugs.
 4. The well system of claim 1, wherein the one or morewellbore projectiles exhibit known magnetic properties detectable by thefirst, second, and third sensors.
 5. The well system of claim 4, furthercomprising: electronic circuitry associated with each of the first,second, and third sensors, the electronic circuitry being configured todetermine whether the corresponding first, second, and third sensorshave detected the known magnetic properties of the one or more wellboreprojectiles; and one or more actuation devices associated with theelectronic circuitry of each of the first, second, and third sensors,the one or more actuation devices being configured to facilitate movingthe first, second, and third sleeves from open to closed positions uponbeing directed by the electronic circuitry.
 6. The well system of claim1, further comprising a diverting agent injected into the first andthird intervals such that the second interval can be stimulatedindependent of the first and second intervals following injection of thediverting agent.
 7. A method, comprising: introducing one or morewellbore projectiles into a work string arranged at least partiallywithin a formation, the work string including a completion assemblyhaving a first downhole tool arranged adjacent a first interval, asecond downhole tool arranged adjacent a second interval, and a thirddownhole tool arranged adjacent a third interval that interposes thefirst and second intervals; detecting the one or more wellboreprojectiles with a first sensor of the first downhole tool and a secondsensor of the second downhole tool; opening first and second slidingsleeves arranged within the first and second downhole tools,respectively, following detection of the one or more wellboreprojectiles; treating the first and second intervals; sealing the firstand second intervals by injecting a diverting agent into the first andsecond intervals; detecting the one or more wellbore projectiles with athird sensor of the third downhole tool; opening a third sliding sleevearranged within the third downhole tool following detection of the oneor more wellbore projectiles; and treating the third intervalindependent of the first and second intervals.
 8. The method of claim 7,wherein detecting the one or more wellbore projectiles with the firstsensor of the first downhole tool and the second sensor of the seconddownhole tool further comprises detecting a magnetic property of the oneor more wellbore projectiles with the first and second sensors.
 9. Themethod of claim 7, wherein opening the first and second sliding sleevescomprises: exposing a plurality of ports defined in both the first andsecond downhole tools; and facilitating fluid communication between aninterior of the work string and the first and second intervals throughthe plurality of ports.
 10. The method of claim 7, wherein treating thefirst and second intervals and treating the third interval compriseshydraulically fracturing the first, second, and third intervals.
 11. Themethod of claim 7, wherein detecting the one or more wellboreprojectiles with the third sensor of the third downhole tool comprisesdetecting a magnetic property of the one or more wellbore projectileswith the third sensor.
 12. The method of claim 7, wherein opening thethird sliding sleeve comprises: exposing a plurality of ports defined inthe third downhole tool; and facilitating fluid communication between aninterior of the work string and the third interval through the pluralityof ports.
 13. The method of claim 7, further comprising: allowing thediverting agent to degrade in the first and second intervals; andproducing fluids from the first, second, and third intervals via thefirst, second, and third downhole tools, respectively.
 14. A method,comprising: detecting a first wellbore projectile with a first sensorassociated with a first downhole tool arranged adjacent a firstinterval; detecting a second wellbore projectile with a second sensorassociated with a second downhole tool and thereby causing the seconddownhole tool to actuate, the second downhole tool being arrangedadjacent a second interval uphole from the first interval; actuating thefirst downhole tool by catching the second wellbore projectile on afirst baffle associated with the first downhole tool and subsequentlypressurizing the work string; detecting the second wellbore projectilewith a third sensor associated with a third downhole tool interposingthe first and second downhole tools and arranged adjacent a thirdinterval that interposes the first and second intervals; hydraulicallyfracturing the first and second intervals via the first and seconddownhole tools, respectively; sealing the first and second intervals byinjecting a diverting agent into the first and second intervals;actuating the third downhole tool by catching a third wellboreprojectile on a second baffle associated with the third downhole tooland subsequently pressurizing the work string; and hydraulicallyfracturing the third interval.
 15. The method of claim 14, whereindetecting the first wellbore projectile with the first sensor comprises:detecting a magnetic property of the first wellbore projectile with thefirst sensor; and actuating the first baffle in response to the magneticproperty being detected.
 16. The method of claim 15, wherein actuatingthe first downhole tool comprises moving a sliding sleeve from a closedposition to an open position where one or more ports are exposed andprovide fluid communication with the first interval.
 17. The method ofclaim 14, wherein detecting the second wellbore projectile with thesecond sensor comprises: detecting a magnetic property of the secondwellbore projectile with the second sensor; and moving a sliding sleevefrom a closed position to an open position with an actuation deviceassociated with the second downhole tool, wherein, when in the openposition, one or more ports are exposed and provide fluid communicationwith the second interval.
 18. The method of claim 14, further comprisingactuating the second downhole tool after a predetermined time periodexpires following detection of the second wellbore projectile by thesecond sensor.
 19. The method of claim 14, wherein detecting the secondwellbore projectile with the third sensor associated with the thirddownhole tool comprises: detecting a magnetic property of the secondwellbore projectile with the third sensor; and actuating the secondbaffle in response to the magnetic property being detected.
 20. Themethod of claim 14, further comprising: allowing the diverting agent todegrade in the first and second intervals; and producing fluids from thefirst, second, and third intervals via the first, second, and thirddownhole tools, respectively.